Rear View Mirror  -  insight into the most promising  Canadian  oil plays.

Canadian Insight

 Cardium Formation - Alberta’s bright spot

 

Alberta’s royalty blunder has been rectified and drilling for oil in Alberta is upbeat. That province remains a leader in conventional Canadian oil and gas drilling activity. The Cardium formation is one of Alberta’s bright spots and oil companies are taking a serious look.

 

Some have compared the Cardium to the Bakken formation but in reality the differences are vast. The Bakken is a higher risk unconventional play still being developed and explored with reserves possibly exceeding 80 billion barrels. Development costs in some cases are much higher. The Cardium is a lower risk fully explored and developed conventional play with recoverable reserves of 7.8 billion barrels.

 

It is estimated that only 17% of the total Cardium reserves have been depleted. Despite the low recovery, production from the Cardium has been on a steady decline and projected to drop off 40% by 2016 if conventional drilling and fracing is continued.

 

Cardium and Bakken are classified as tight shales with encased oil bearing reservoirs. Both formations were discovered in the 1950's and both produce high quality crude oil, but the similarity ends here. Oil reservoirs in the Bakken are at depths somewhat greater than that of Cardium. In some cases, Bakken oil pools may reach 11,000 feet below the surface. Cardium wells are shallower and oil reservoirs can be found anywhere from 3600 to 8100 feet beneath ground level.

 

Advanced horizontal drilling technology and multi-stage fracing methods have brought back interest to the fifty year old Cardium formation. Had it not been for new technological drilling and fracing advances developed for the Bakken, Cardium’s future oil production would slowly sputter to a stop in the next two decades. Alberta may be thankful in the short run for the technology developed specifically for the Bakken and now adapted for the Cardium.

 

The Cardium formation stretches over 600 miles from the U.S. and Alberta border along foothills to Dawson Creek. The formation is wedge shaped and thickness varies from 450 feet on the western edge to less than 50 feet on the eastern edge. The width of the formation averages about 120 miles. This formation touches into south western Saskatchewan and northern Montana. The Cardium is a part of Western Canada Sedimentary Basin.

 

There are over 14 separate oil and gas fields composing the Cardium formation. Some of the most famous are: Pembina, Willes den Green, Ferrier, Ricinos, Cy-Pem, Carrot Creek, Garrington, Crossfield, Caroline, and Kakwa. It is estimated that there are over 297 oil and 289 gas pools in the Cardium .

 

In 1953, Mobile Oil made the very first oil discovery in the Pembina field. This discovery well is still in production and has produced over 800,000 barrels in the past 57 years. Drilling in the Cardium prior 2004 had dropped off to about 28 wells annually. Since 2004, interest has regained and there are approximately 140 or more wells drilled yearly. Some estimates indicate that there may be close to 6000 wells in production in the formation.

 

Unlike Saskatchewan’s Bakken, the Cardium has been drilled extensively and every field in the formation has been explored and documented. There are no surprises or hidden quantities in the Cardium. It’s all a matter of employing new multilateral and horizontal drilling and multi-stage fracing to sustain profitable productivity with each new well. It is possible that conventional wells in the Cardium will continue to drop off in productivity if horizontal well drilling techniques intensify.

 

It is clearly evident that the Cardium will be a popular play in 2010. The production gains from that one formation will be without a doubt a big boast for Alberta’s conventional oil production. Many oil and gas companies which are involved in this play may improve their balance sheet providing that oil stays above $70/bbl.

 

The very near future of the Cardium looks very promising but....in the long run it may result in a fast depletion if the Alberta government is not careful in regulating its drilling activity. This formation needs diligent, careful and controlled management. If properly managed, Cardium oil and gas production may last for the next future generation.

 

By J. Klemchuk

 

Technology opening doors to Saskatchewan’s heavy oil

 

To understand heavy oil development in Lloydminster, you must be prepared to look at the history and the problems associated within the area. Less than 10% of the total estimated heavy oil reserves have been extracted since the first discovery was made over sixty-six years ago.

 

Oil in the Lloydminster area is classified as heavy and some oil samples have shown an API gravity of 6°. Most of the heavy oil in the Sparky Formation has an API gravity of 9° to 18°. This is difficult oil to work with and the sand and shale formation mixed with water adds to the problem.

 

The Sparky Formation was named after one of the operators that drilled the first producing heavy oil well near Lloydminster. The formation is shallow and the oil bearing zone is situated at depths of 1780 to 1950 feet. Thickness of the formation is up to 130 feet. Composition is sand and shale with significant amounts of water.

 

Exploration in Saskatchewan’s Sparky Formation began over ninety years ago. Imperial Oil was the first oil company to do considerable exploratory work from 1919 to 1920. Two years of drilling netted Imperial Oil twenty dry holes which would eventually fill with salt water.

 

Imperial’s reports showed non-commercial traces of oil in their exploratory wells near Lloydminster. The oil company had enough and aborted all future drilling plans in the Lloydminster area.  It moved on to Alberta and Norman Wells area of the North West Territories.

 

Farming and local residents in the Lloydminster all knew that there was oil in the area. Most had experienced problems with oil seeps on their farm land. Low lying areas (sloughs) which filled with water every spring posed a great risk for livestock. Samples submitted to laboratories proved that there was oil contamination in the water from oil seeps.

 

Imperial Oil Ltd. was the only big oil company to drill near Lloydminster prior to Second World War. Countless small oil companies went bankrupt in the next twenty five years doing exploration and drilling. Some reorganized, continued drilling dry holes and went bankrupt again.

 

In 1939, a small oil company named Lloydminster Royalties was organized and it made the first oil discovery near Lloydminster. The well produced an estimated 250 barrels during the first day. Unfortunately, that was the one and only day oil was produced from that well. Next morning, the well filled with salt water. The good outcome was that it enticed others to continue.

 

Finally, in 1943, another locally organized oil company (Burroughs and Sparks) drilled the first commercial producing oil well 4 miles southeast of Lloydminster. The well named Sparky #1 produced heavy oil for several years before it became plugged with mud and sand and was abandoned.

 

These two oil discoveries attracted a major player to the area. Husky Oil which was drilling in the northern states heard the news and decided to come to try their hand in heavy oil. Husky began drilling in 1946. The company’s success led to heavy oil development and a refinery at Lloydminster.

 

By the early seventies, Lloydminster heavy oil attracted Mobil Oil, Norcen Energy Resources, Dome Petroleum and Home Oil Company Ltd. Hundreds of oil wells were drilled but slowly the enthusiasm waned as continuous wellbore problems persisted.

 

Screw pumps were employed instead of the conventional jerk pumps. A variety of screens were tried to separate the sand from the oil. Wellbore problems persisted. Some wells plugged with sand and mud in less than a week after coming on stream. Others saw premature subsurface pump failures, casing and tubing corrosion and wellbore mudblocks. In some wells saltwater was a very contentious disposal issue.

 

Conventional recovery methods have proven to be expensive. Maintaining wellheads and wellbores is a big business in the Lloydminster area. It has become a separate money making industry. Wells must be serviced frequently. This not only adds to cost of production but creates a production loss if service and repair is delayed.

 

A variety of non-conventional methods have been tried to extract heavy oil; CHOPS, SAGD, and Vapex have been used. All have had their limited success, but each has its associated problems. High costs are the major limiting factor.

 

Petrobank and its THAI™ technology may unlock the doors to the huge Lloydminster heavy oil fields. THAI™ should eliminate previous problems associated with conventional means. It’s a process that has been proven to work in heavy oil and bitumen. Reports indicate that it is far more economical to extract heavy oil out of the Sparky Formation then that of the Canadian oil sands.

 

Estimates are that the Lloydminster heavy oil reserves may be as high as 30 billion barrels. Petrobank claims that using its patented THAI™ process, a potential 20 billion barrels may be recovered. If this process succeeds, Saskatchewan may catapult into a major conventional oil producer.

 

By J. Klemchuk  

 

 

British Columbia’s Gems - the Horn River Basin and Montney Play

 

A look at why the province of British Columbia is reaping billions of dollars in revenue from its oil and gas land sales. Here are the reasons why that province is attracting more attention than its sister province Alberta from the exploration companies.

 

Two of the three hottest plays in Canada have netted British Columbia 2.7 billion dollars in revenue in 2008. It’s a very sizeable shot of revenue for any government. Never in Canadian oil and gas history has any province seen such interest in land sales.

 

Politics and oil often cause a very unpredictable volatile mix. In 2007 the province of Alberta, prior to the provincial election, appointed a royalty review panel to recommend new oil and gas royalty rates. The panel recommended considerable increases in royalties. Oil companies protested the panel’s recommendations but the province showed intent to proceed with royalty increases.

 

Alberta’s government idled while British Columbia and Saskatchewan courted the oil and gas companies. Both provinces dangled promises to the oil and gas companies that there would be no immediate and foreseeable increases in royalties. Early in 2008 oil and gas companies exited in droves from Alberta into Saskatchewan and British Columbia.

 

Finally the Stelmach government agreed to sit down and listen to the oil and gas companies’ grievances, but the response was too little and too late. The province of Alberta addressed the situation after the oil industry’s exodus.

 

Some of the oil and gas companies ventured to Saskatchewan’s hot spot, the Bakken Play. Others saw an opportunity in northeastern British Columbia. These companies chose to move across the provincial borders into British Columbia because they were familiar with the Montney formation in the Peace River Arch of Alberta.

 

EnCana’s pioneering exploration in the area led to the discovery of the Montney in 1993. The eastern side of the formation is nestled with pockets of oil as well as natural gas reservoirs. The Montney shale formation proceeds up slope to the northwest. The formation is wedge shape. Its thickness ranges from 3 to 80 feet on the Alberta side and gradually deepens on the British Columbia’s side up to 700 feet. The formation is 175 miles wide and 200 miles long.

 

The Montney is characterized by its variability as it proceeds into British Columbia. It is a mix of sandstone, siltstone and shale. Porosity varies from 6 to 9 percent in the Dawson Creek and Swan Lake area. Tracts of land now being purchased for exploration are as low as 3% in porosity. This exemplifies a very tight shale formation.

 

The Montney on the British Columbia side is viewed with great potential for unconventional natural gas. Current estimates evaluate the Montney to contain 500 trillion cubic feet in place and a probable recovery of 50 trillion cubic feet. Recovery rates are estimated to be 10 to 20%.

 

Ten years after the Montney discovery, EnCana made another big natural gas field discovery, Horn River Basin. It is situated more than 200 miles north of Fort Nelson. Horn River Basin comprises of five formations, Key River, Evie, Otter Park, Fort Simpson and Muskwa. Early evaluations place Horn River to be Canada’s largest field of unconventional natural gas.

 

Exploration reports by EOG Resources state that the Muskwa shale formation in the Horn River Basin is 500 feet thick and has a porosity of 4%. This compares to the Texas Barnett formation which has a porosity of 4.5%. EOG reports that the silica content to be 10% better then that of the Barnett formation. This quality gives the Horn River Basin reservoir an excellent production potential.

 

Recent estimates place the Horn River Basin at 750 trillion cubic feet in place and recoverable reserves of 75 trillion cubic feet; this is more than twice the size of the Texas Barnett Shale play which is estimated to have recoverable reserves of 30 trillion cubic feet. The Barnett shale field produces 3.5 billion cubic feet of unconventional natural gas per day.

 

Experts estimate British Columbia’s shale formations may hold a possible 250 trillion cubic feet of recoverable unconventional natural gas from all possible sources. Even if these figures are off by 50%, British Columbia may eventually become a major natural gas producer in Canada.

 

It is believed that Canada’s conventional sources of natural gas peaked as early as the 1980's. The Canadian Society for Unconventional Gas predicts that 50% of our nation’s natural gas will come from shale sources by 2025.

 

It must be cautioned that Canada’s unconventional natural gas is still in its infancy. The unconventional natural gas industry is learning and is in experimental stages. Knowledge is being passed on from the Barnett Play to assist exploration and development of Montney and Horn River Basin.

 

Gas recovery rates are variable and largely dependant on the porosity and permeability of the shale gas reservoir. Present development costs reported by ARC Energy Trust are at $10 per barrel equivalent.  Other companies state that gas prices must be above $9 to break even.

 

Recovery of natural gas from shale formations necessitates expensive horizontal or multilateral drilling from a single pad. Eight to twelve-stage hydraulic fracturing using millions of gallons of water and sand is necessary to achieve viable flow rates of 4 to 8 Mmcf/d. The shale porosity and density vary from well to well and fracturing techniques must be tailored at each wellhead.

 

Unconventional natural gas wells do have a long life expectancy. Natural gas that is locked in shale formation has nowhere to escape. While initial flow rates are lower than conventional reservoirs, wells may produce from 20 to 30 years.

 

The biggest obstacle exists that there is no infrastructure in the potential gas exploitation area. Roads, pipelines and gas plants must all be built. It is very difficult to move drilling rigs and equipment. Terrain conditions are rugged and muskeg conditions are prevalent. In many instances exploration and drilling is only possible when the ground is frozen. Costs can be astronomical.

 

There is a sense of much optimism by the oil and gas companies involved in these two plays. Companies are spending huge sums of money and committing to increase their spending budgets.

 

Last November EnCana submitted a proposal to British Columbia’s provincial regulators to construct a multibillion dollar natural gas plant in northeastern British Columbia.  If approved by the B.C. regulators, EnCana’s proposal to proceed in constructing an integral element may define the future of Horn River and Montney, and the future of shale gas in British Columbia.

 

By J. Klemchuk  

 

Prospects for Yukon’s shale plays

There has been much hype about the northern shale plays by our media. Several very notable newspapers in eastern and western Canada suggest the Canadian north is on the verge of a major shale oil discovery exceeding even the Bakken. We will examine the latest facts and let you make the decision where the truth lies.

 

Oil and natural gas discoveries are not new to Canada’s Northwest Territories. The presence of oil was first reported by Alexander Mackenzie in the late 1790s. Imperial Oil made the first major oil discovery southwest of the community of Norman Wells, North West Territories in 1919.

 

With the oil discovery came the construction of a refinery in Whitehorse, Yukon in 1937. It specialized in aviation fuel. In 1942, the Canol pipeline was constructed from Norman Wells to Whitehorse.  The pipeline was constructed from a four inch pipe and its capacity was very limited.

 

In 1986, a twelve inch pipeline, Norman Wells pipeline, was constructed from the northern oil field into Zama, Alberta.  It was at this time that Imperial Oil ramped up its production from the north.

 

Exploration activity from 1960 to 1970 reached record heights. A total of 76 exploratory wells were drilled in the Mackenzie Plain but no major oil discovery was ever made.  Natural gas shows were quite evident.

 

Oil exploration for the north stopped in 1977 when the Liberal government in Ottawa froze all exploration rights for the north. Intent was to facilitate a quick settlement of Aboriginal land claims. Unfortunately, it wasn’t until 1994 that the land claims for the region were finally completed.

 

To date, the Norman Wells oil fields remain to be the major oil discovery in the North West Territories. This northern oilfield has been in production for 92 years. During that time, the field has produced well over a quarter of a million barrels of light sweet crude oil.

 

Six years ago, Canada’s federal government agreed to a partnership with the Yukon Territory and organized an assessment of potential areas where hydrocarbons were the most probable.  Diamond drilling would evaluate the strata along the Richardson Mountains in the Eagle Plain Basin.

The two governments began exploratory operations in Canada’s northern territories in 2007.  Hundreds of core samples were collected when diamond drilling ended in 2009. Three potential formations were targeted along the Richardson Mountains. Road River Group, Canol and the Imperial formations.

 

X-ray diffraction was taken in the three potential areas to determine mineral composition of the shale. Core samples were collected over an area which stretches 110 kilometers in a northerly direction. The study encompasses the Peel and Porcupine Rivers and northwest of the Dempster Highway. Core samples collected were sent and analyzed at a laboratory in Calgary.

 

In 2010, the core samples were all evaluated and results were cataloged and later published. During that year, geologists helped prepare a 74 page report, Shale gas potential of Devonian shale in north Yukon: Results from a diamond study in western Richardson Mountains. This report is readily available for those who wish to read it.

 

Results indicated a very good oil potential in the Canol formation.  Core samples from the Canol and the Road River Group showed a high organic carbon content with high values of silica and quartz. The Canol samples exhibited high quartz values. This type of strata has a high potential to host unconventional hydrocarbons and is the most suitable for hydraulic fracturing.

 

Results from the Road River Group and Imperial formations suggest a good potential for natural gas as these hydrocarbon deposits are more mature than that of the Canol. Mature strata will result in the hydrocarbons transformation.  Kerogen, oil and liquefied gases will eventually turn into natural gas through time.

 

The report has certainly shed some light on a specific area in northern Yukon which has the most probable chances of a significant oil and shale gas discovery. The gathered information has certainly drawn a roadmap for future exploratory work in the northern Yukon.

 

This is the present reality. Drilling costs in the far north compared to central Alberta may exceed by as much as 300%. It is difficult to perceive high exploration activity in the northern territory when oil prices hover at or near $85 per barrel.

 

By Jim Klemchuk

 

 

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Lower Shaunavon – Saskatchewan’s stealth oil play

 

Higher oil prices, smaller land base choice and overheated land sales in Alberta are driving back oil companies seeking highly prospective oil plays into Saskatchewan. Last three provincial land sales indicate that southern Saskatchewan and in particular lower Shaunavon is the prime choice.

 

The Shaunavon formation is composed of two members with different properties. Both members were formed in the Bathonian age and are situated in Western Canadian Sedimentary Basin. The upper unit is composed of sandstone, limestone or dolomite. The lower member is made up of microcrystalline limestone situated below sedimentary bedrock of oolite (egg stones).

 

The Shaunavon formation presently consists of 131 discovered oil pools and has a current assessment of 2 billion barrels of discovered oil in place. Canada’s National Energy Board estimates that there are an another 896 undiscovered oil pools and an additional 3.3 billion barrels of crude oil in place.

 

The lower Shaunavon member has an oil bearing zone at 4,388 feet or 1350 meters. The pay zone is from 13 feet (4 meters) to 52 feet (16 meters). Oil is rated as medium crude with gravity range of 18° to 22° API. Prior to introduction of horizontal drilling and multi-stage fracturing, this play was not an economical reservoir.

 

First discovered in 1953, lower Shaunavon formation now looks very promising with the event of advanced technology. A decade ago, a lower Shaunavon well averaged at 10 to 15 barrels per day of medium grade crude oil from a vertical well. Production in the area has made a dramatic jump. Some oil companies report a first year average of 100 barrels per day, declining to and stabilizing at 60 barrels per day in the following year.

 

There are several incentives which are enticing oil companies into the region. Large land tracts of lease land are still available at competitive prices. The potential of new discoveries are very high according to NEB data.

 

In 2010, the Saskatchewan government extended favorable royalty and regulatory practices. New horizontal wells are exempt from royalties on the first 100,000 barrels (2.5% mineral tax applies and must be paid). Drilling permits are done promptly and turnaround time is expeditious.

 

Alberta’s oil plays are quickly becoming congested with an abundance of participating oil and gas companies. Alberta land prices are continuing to climb. Saskatchewan offers much potential and the lower Shaunavon oil play will be difficult for most to resist.

 

By J. Klemchuk

 

Priming the pump for Manitoba sweet crude

 

Competition amongst Canada’s western provinces has always been keen in the oil patch.  Every province has its own royalties and incentive programs structured to entice and maintain new developing reserves. One slip up and companies will leave in droves into neighboring provinces. Luring back lost interest can be costly and difficult.

 

Smaller players like Manitoba have to be vigilant to maintain and lure new exploration and development. Alberta, British Columbia and Saskatchewan are well noted beyond the borders for their large oil and natural gas reserves. Frequently, their scheduled crown land sales play an important role in attracting oil companies into prospective and renowned plays.

 

Manitoba, the small kid on the block, has seen its share of ‘boom and bust’ in the past sixty years. Slumping oil prices throughout history have had a more negative effect on the oil patch in Manitoba than in Alberta but …. It’s much, much brighter in Manitoba’s oil patch now.

 

Manitoba’s first oil boom started with the discovery of the famous Daly field in early 1951. The field, located fifteen miles west of Virden, was first explored by three major oil companies – California Standard, Shell Canada and Imperial oil. Each company contributed to drilling a total of eight wells with some shows of oil.

 

On February 1, 1951, California Standard discovered the first commercially viable oil well. This well quickly led to the development of Manitoba’s first oil field, the famous ‘Daly field’. This continued to discoveries at Lulu Lake, Waskada, Tilston, Virden and Roselea.  By 1956, Manitoba had 359 wells and 12 discovered oil fields.

 

Waterflooding was approved by the provincial government in 1960. This was in direct response to companies’ requests for enhanced production in the Daley and Virden oil fields. By 1968, Manitoba’s oil production surpassed an average of 16,500 barrels per day but began to drop until 2004 when production slipped to 11,000 barrels per day. Today, Manitoba’s production has doubled in the past seven years and now is within striking distance of 30,000 barrels per day.

 

The Manitoba government held its first land lease sale and introduced the ‘holiday volume’ incentive program in 1979.  Another successful stimulant was implemented in 1987, ‘Enhanced Oil Recovery Program’. These two incentives brought another boom to Manitoba’s oil patch. In 1980, a second formation was discovered, Spearfish Formation.

 

In 1985, a Daly well was drilled beyond the licensed depth which resulted in the discovery of the Bakken Formation. This accidental discovery enticed other companies to explore at deeper depths. Eventually, this has lead to the discovery of two more formations, the Jurassic Melita formation in 1993 and Devonian Three Forks Formation and the Sinclair Field in 2004.

 

The oil producing region in south western Manitoba has the highest private mineral rights ownership in Western Canada. Many landowners settled in the province prior 1890. After this date, the federal government took over the mineral rights throughout Western Canada.

 

Eighty percent of all mineral rights in Manitoba’s oil patch are still held privately. The crown holds a paltry 20%. In comparison, the provincial government of British Columbia holds 95%, Alberta 81% and Saskatchewan 78% of all provincial mineral rights.

 

Privately held mineral rights have slowed oil exploration and development in Manitoba. It is far more difficult to deal with multiple mineral rights owners than one provincial authority. During the past decade, mineral rights brokers have eased the situation. Landowners can now place their land to be tendered on broker’s tendering lists.

 

Land owners are offered several dollars per acre to several hundred dollars and may involve a substantial signing bonus. Some are as high as $50,000; most are a fraction of this amount. Crown land sells at an average of $260. Bids may be much higher in both instances pending how desirable the land is.  The most attractive area of the province is straddling the Saskatchewan and U.S. border north to Waskada.

 

Drilling and completion cost between Manitoba and North Dakota are several light years apart. A fully completed Manitoba horizontal well drilled into the Bakken formation costs from $1.2 to $1.5 million. A fully completed horizontal well drilled into the Bakken in North Dakota exceeds $5 million. The difference in cost is directly linked to expensive drilling depths and higher land costs.

 

It is true that North Dakota’s wells out produce those of Manitoba but the bottom line… costs in Manitoba Bakken oil range from $15 to $20 per barrel. In comparison, those in North Dakota run from $45 to $60 per barrel.

 

Manitoba government continues to use incentives to attract and promote its oil industry. The ‘holiday volume’ on horizontal and injection wells has been extended to 2015.

 

Last year, 516 successful wells were drilled in that province. Petroleum Services Association of Canada forecast that there will be another 550 new Manitoba wells place on production this year. Drilling interest in Manitoba’s oil patch is red hot.

 

By J. Klemchuk

 

The Bakken Oil Formation — Hottest Oil Play

 

If you haven’t heard about the “Bakken’ then surely you have been away, far away from the media. It’s not a new discovery; call it a rediscovery. Initially the Bakken formation was discovered in 1957 in Saskatchewan. It’s an unconventional play that was ruled out as unprofitable using conventional drilling.

 

The formation lies in the Williston Basin and covers more than 518,000 square kilometers. It is more than 3500 meters below the surface in parts of North Dakota and Montana. The formation which covers Southwestern Manitoba and Southeastern Saskatchewan is much shallower and oil can be struck at depths of 900 to 1600 meters.

 

It is 300 meters below the Mississippian Formation. Oil reservoir pressures are low on the Canadian side and much greater on the Southern tips of Montana, North and South Dakota. This is due to the far greater depths that the formation is situated.  With today’s technology CO2 injection makes this an issue of irrelevance .

 

The Bakken shale comprises of three distinct layers. The upper and lower layers have distinct properties of non- porous hard rock  and the middle layer have the features of a conventional oil reservoir. The middle oil bearing layer may be five to 12 meters thick but there are pockets where thickness may exceed 17 meters.

 

It is true that the American share of the Bakken is much greater than on the Canadian side. It is possible that the Americans may have 2/3's of the hidden treasure. It is far more risky to drill in North and South Dakota as well as Montana than in Manitoba or Saskatchewan. Thus, it is more profitable and less risky to drill on the Canadian side.

 

Why all the excitement over the Bakken now? Recent months have seen crude oil reach historical record highs of $120 /bbl. Estimated costs of recovery on the Canadian side is a little over five dollars per barrel over a span of 6 years . This is based on a well production of 200 bbl /day and the price of oil is over $100/bbl.. Compare the costs of developing an off shore oil field or the tar sands and you can see where the profits lie.

 

With global consumption reaching staggering limits and high quality crude getting much more difficult to find, there lies the reason for Bakken exploration and development. Oil from this formation is of very high quality.

 

Bakken oil is the best in the world. It grades at an average of 42° API and some samples testing at 47°API. This surpasses the quality setting  standards of the Saudi Arabian sweet crude. As an example, the oil from  Ghawar field in Saudi Arabia averages at a mere 34° API.  The tar sands of Venezuela average is a low 8.5° API and that of Alberta oilsands grades at 10° API.

 

The low API grades require special extraction and refining technology. These costs exceed $50/bbl while that of the Bakken are a mere $5/bbl. Take the premium of up to $5/bbl  for high quality sweet crude into account and it’s easy to see why there is excitement over the Bakken.

 

We often hear a variety of figures as to what the total reserves of the Bakken formation are. Some figures only add confusion. I firmly believe in the figures released by the US Energy Information Report in 2006. The US Energy Information (EIA) Report states, “Estimates ranging up to 503 billion barrels of potential resource is in place.”

 

While the lion’s share of the Bakken oil lies within US soil, Canada’s share is approximately 30 % of the EIA estimates. Saskatchewan’s reserves in the Bakken may well be in excess of 100 to 150 billion barrels of sweet crude.

 

Recoverable rates have been low balled at 1 to 2% recovery; these are extremely low values. It’s unacceptable to think that only 1.5 billion barrels of crude will eventually be recovered.  New technology is quickly being developed. Bakken recovery may be a more realistic 15% and may increase to higher levels with newer developments.

 

The cutting-edge technology that now is in place will further advance at even more of a rapid pace.  Horizontal and directional drilling techniques are being perfected. In some instances the horizontal leg is far greater than the initial vertical entrance.

 

Advanced hydraulic fracturing technology developed by Petrobank Energy and Resources  injects  massive amounts of sand into the oil bearing formation. This results in higher porosity resulting in increased flow rates from the reservoir.

 

Inherent problem in the Bakken is that reservoir pressures are low. This is more so on the Canadian side where formation depths are at far lesser depths than on the US side. This is no longer a limiting factor. Technology is now in place where reservoirs can be pressurized with carbon dioxide and substantially increase flow rates.

 

Saskatchewan has considerable reserves of coal in very close proximity of the Bakken. SaskPower, provincial supplier of electricity, has large coal fired steam turbine generators near Estevan at Boundary Dam.

 

Prior to the provincial election, SaskPower faced a very serious problem in eliminating the pollution from their coal fired generators. Recently the Federal Harper Government has come to the rescue and has offered financial assistance in modernizing the polluting coal fired generators. This could have not come at a more opportune time.

 

What once appeared as a very serious environment issue for the provincial supplier of electricity has now turned into a more positive development. SaskPower can now expand their coal powered generators using new technology and profit from sequestering the huge amounts of carbon dioxide for the Bakken to pressurize oil reservoirs.

 

To the companies who decided to leave Alberta because of the royalty issue, the Bakken is an enticing alternative. Premier Brad Wall and Minister of Energy and Resources, Bill Boyd have made a strong pitch to the oil industry.

 

Brad Wall has reaffirmed that there will not be a sudden royalty increase as occurred in Alberta. “There will not be an increase in royalties for years to come”. This in itself is a strong message to the oil companies in welcoming them.

 

By J. Klemchuk

The reality behind Alberta southern basin — ‘Exshaw Bakken Play’  

 

Most of our readers are well acquainted with the Bakken and associate it to southeastern Saskatchewan, southwestern Manitoba and northern half of the state of North Dakota. This region is well noted for its high quality crude oil and its large reserves.

 

News during the past year has spread that southern Alberta and northern Montana may have been blessed with an extension of the famous Bakken. It’s an area which has eluded the buzz and excitement of oil exploration. This new discovery has been dubbed the Exshaw Bakken but is it really an extension of the Bakken?

 

Geological data indicates that Alberta southern basin is not a part of the Bakken. It is a separate resource play. It is true that both plays were formed during the same time frame (late Devonian to early Mississippian), but each formation shows different depositional settings and is separated by several hundred miles.

 

The Exshaw shale formation, part of which the Alberta southern basin is located, is enormous. It stretches from Montana northwards along western Alberta, in through northeastern British Columbia and then into the Northwest Territories. The formation is composed of black shale, siltstone and limestone.

 

The Alberta southern basin is a very small part of the Exshaw shale formation. The basin nestles almost equally in Montana and Alberta. It is oval shaped, and approximately 100 miles wide through the center and 140 miles long. Its longest diameter runs north and south. For comparison, the Alberta southern basin is small compared to the Bakken and occupies approximately ten percent of the equivalent area.

 

Several years ago an American oil company, Rosetta Resources Incorporated, based in Houston, Texas acquired 20,000 acres of Alberta basin lease land from the Blackfeet Nation in Montana.  In 2009, Rosetta drilled on this property a vertical exploratory well, Gunshot 31-V16, and discovered oil saturated core samples.  Logging verified oil in four separate zones and quantities were insufficient for commercial production.

 

Rosetta followed up with another vertical well to a depth of 4837 feet and in the midst, the drill rig operators changed the drill bit angle and continued at a lateral depth to over 4100 feet. In reality, Tribal Gunsight 31-16H was transformed into a horizontal well.  When drilling was completed, it had a total measured depth of 9206 feet. This well was fractured and completed and seemed to be a viable producer based on rumor.  Rosetta didn’t disclose publically the well’s production.

 

Following the completion of the horizontal well, Rosetta drilled three delineation vertical wells spaced approximately 28 miles apart. Cores and logging samples were studied and company geological engineers evaluated the reserves to hold 12.5 million barrels in place on the company holdings.

 

The Rosetta oil find was touted by the media to be a part of the Bakken extension. It sparked immediate interest on both sides of the border. On the Montana side, Newfield Exploration, Murphy Oil, and Quicksilver Resources jumped at the opportunity, each accumulated significant land acquisitions. They were later joined by Abraxas Petroleum, Anschutz, and Stone Energy Corporation. Many more have jumped onto the bandwagon since.

 

North of the border, Crescent Point Energy and EnCana Corporation loaded up on sizable holdings. It is estimated that Crescent Point holds in excess of half a million acres and EnCana has approximately 650,000 acres. Bowood Energy holds 65,880 acres and DeeThree has scrounged up 108,000 acres.

 

Interest in the area is building even though there is no evidence of a real major oil discovery. Clearly, the biggest winner is the government of Alberta. It has raked in almost $200 million in land sales for the southern basin in the past ten months.

 

Land sales on the Alberta side have been as high as $1800 per acre. South of the border sales have been much lower and range from $1.50 to $1300 per acre; the average Montana leases sell at $100 to $200.

 

Several rumors on the American side have surfaced that one of the horizontal wells drilled by Newfield Exploration Company was producing almost 100 barrels per day.  These hearsays were based on the number of holding tanks placed beside the well; this is hardly proof as to the well’s production numbers.

 

Time will tell whether the Alberta southern basin is a significant or viable discovery. The potential is there but many questions remain. It’s still a speculators play but… notable companies such as Crescent Point, EnCana, and Murphy Oil rarely commit large expenditures into exploration if odds of success are not favorable.   

 

J. Klemchuk